Devices, systems, facilities, and processes for liquefied natural gas production

ABSTRACT

Devices, systems, and methods for liquefied natural gas production facilities are disclosed herein. A liquefied natural gas (LNG) production facility includes a liquefaction unit that condenses natural gas vapor into liquefied natural gas; an electric-driven compression system for the refrigerant(s) in power to the liquefaction unit; and a sequestration compression unit configured to compress and convey at least one CO2-rich stream towards a sequestration site, thereby reducing the overall emissions from the LNG facility.

PRIORITY CLAIM AND CROSS-REFERENCE TO RELATED APPLICATIONS

This application is a continuation-in-part of U.S. patent applicationSer. No. 17/003,567, filed Aug. 26, 2020, entitled LIQUID NATURAL GASPROCESSING WITH HYDROGEN PRODUCTION, the entire contents of which areincorporated by reference herein and relied upon.

BACKGROUND

Energy facilities such as liquefied natural gas facilities and naturalgas power plants contribute to greenhouse gasses. Greenhouse gasescomprise various gaseous compounds including, carbon dioxide, methane,nitrous oxide, hydrofluorocarbons, perfluorocarbons, and sulfurhexafluoride, that absorb radiation, trap heat in the atmosphere, andgenerally contribute to undesirable environmental greenhouse effects.

Liquefied natural gas facilities and natural gas power plants oftenimplement certain forms of hydrocarbon emissions conversiontechnologies, such as thermal oxidizers and flares, to converthydrocarbon emissions into carbon dioxide. Typically liquefied naturalgas facilities and natural gas power plants do not incorporategreenhouse gas removal technologies. Sources of greenhouse gases inliquefied natural gas facilities and natural gas power plants typicallyinclude gas turbine exhaust(s), thermal oxidizers, various flares, andmarine vent systems.

Liquefied natural gas production facilities and related processes forproducing liquefied natural gas in a facility, as well as natural gaspower plants and related processes for producing natural gas power, needto improve the overall efficiency of the facility and reduce greenhousegas emissions.

SUMMARY

In light of the disclosure herein, and without limiting the scope of theinvention in any way, in a first aspect of the present disclosure, whichmay be combined with any other aspect listed herein unless specifiedotherwise, a liquefied natural gas (LNG) production facility includes aliquefaction unit and a gas turbine. The liquefaction unit condensesnatural gas vapor into liquefied natural gas. A fuel to the gas turbinecontains at least about 90% hydrogen by volume.

In a second aspect of the present disclosure, which may be combined withany other aspect listed herein unless specified otherwise, the LNGfacility further includes an on-site hydrogen generation unit thatprovides hydrogen to the gas turbine.

In a third aspect of the present disclosure, which may be combined withany other aspect listed herein unless specified otherwise, the hydrogengeneration unit is a steam reformer.

In a fourth aspect of the present disclosure, which may be combined withany other aspect listed herein unless specified otherwise, the LNGfacility further includes at least one capture unit that generates aCO2-rich stream from the products of the steam reformer.

In a fifth aspect of the present disclosure, which may be combined withany other aspect listed herein unless specified otherwise, the LNGfacility further includes a sequestration compression unit configured tocompress and convey at least one CO2-rich stream from a capture unit,towards a sequestration site, thereby reducing the overall emissionsfrom the LNG facility.

In a sixth aspect of the present disclosure, which may be combined withany other aspect listed herein unless specified otherwise, thesequestration site comprises an underground geological formationcomprising an at least partially depleted hydrocarbon reservoir.

In a seventh aspect of the present disclosure, which may be combinedwith any other aspect listed herein unless specified otherwise, thesequestration site comprises a region on top of a seabed, said regionlocated at a depth greater than about 3.0 kilometers below sea level.

In an eighth aspect of the present disclosure, which may be combinedwith any other aspect listed herein unless specified otherwise, thesequestration site comprises a region below a seabed.

In a ninth aspect of the present disclosure, which may be combined withany other aspect listed herein unless specified otherwise, the LNGfacility further includes an acid gas removal unit configured to acceptraw feed natural gas and to generate an acid gas stream, a flash gasstream, and a purified natural gas stream. The acid gas stream isdirectable to the sequestration compression unit.

In a tenth aspect of the present disclosure, which may be combined withany other aspect listed herein unless specified otherwise, the flash gasstream is directable to the sequestration compression unit.

In an eleventh aspect of the present disclosure, which may be combinedwith any other aspect listed herein unless specified otherwise, theflash gas stream is directable to the steam reformer for use as afeedstock to the reformer.

In a twelfth aspect of the present disclosure, which may be combinedwith any other aspect listed herein unless specified otherwise, thesequestration compression unit comprises a compressor driven by steamfrom the steam reformer.

In a thirteenth aspect of the present disclosure, which may be combinedwith any other aspect listed herein unless specified otherwise, thecapture unit includes an amine absorber and liquid amine absorbent forabsorbing CO2. The steam reformer generates excess steam. The excesssteam is directable to the capture unit to provide heat for regeneratingthe liquid amine absorbent.

In a fourteenth aspect of the present disclosure, which may be combinedwith any other aspect listed herein unless specified otherwise, thecapture unit includes a chilled ammonia process for absorbing CO2, thesteam reformer generates excess steam, and the excess steam isdirectable to the capture unit to provide heat for regenerating theammonia absorbent.

In a fifteenth aspect of the present disclosure, which may be combinedwith any other aspect listed herein unless specified otherwise, the acidgas removal unit includes an amine absorber and liquid amine absorbentfor absorbing CO2, the steam reformer generates excess steam, and theexcess steam is directable to the acid gas removal unit to provide heatfor regenerating the liquid amine absorbent.

In a sixteenth aspect of the present disclosure, which may be combinedwith any other aspect listed herein unless specified otherwise, the acidgas removal unit includes a chilled ammonia process for absorbing CO2,the steam reformer generates excess steam, and the excess steam isdirectable to the acid gas removal unit to provide heat for regeneratingthe ammonia absorbent.

In a seventeenth aspect of the present disclosure, which may be combinedwith any other aspect listed herein unless specified otherwise, the LNGfacility further includes a dehydration unit including a solidadsorbent, the dehydration unit configured to receive the purifiednatural gas stream from the acid gas removal unit and to provide a drypurified natural gas stream, the steam reformer generates excess steam,and the excess steam is directable to the dehydration unit to provideheat for regenerating the solid adsorbent.

In an eighteenth aspect of the present disclosure, which may be combinedwith any other aspect listed herein unless specified otherwise, thesteam reformer generates excess steam, and the excess steam isdirectable to the sequestration unit, and the sequestration compressionunit comprises a compressor driven by the excess steam from the steamreformer.

In a nineteenth aspect of the present disclosure, which may be combinedwith any other aspect listed herein unless specified otherwise, thesteam reformer generates excess steam, and the excess steam isdirectable to drive a compressor.

In a twentieth aspect of the present disclosure, which may be combinedwith any other aspect listed herein unless specified otherwise, thesequestration compression unit comprises a compressor driven by anelectric motor.

In a twenty-first aspect of the present disclosure, which may becombined with any other aspect listed herein unless specified otherwise,the sequestration compression unit comprises a compressor driven by thegas turbine.

In a twenty-second aspect of the present disclosure, which may becombined with any other aspect listed herein unless specified otherwise,the sequestration compression unit comprises a compressor driven by ahydrogen turbine configured to be driven by hydrogen from the steamreformer.

In a twenty-third aspect of the present disclosure, which may becombined with any other aspect listed herein unless specified otherwise,the LNG facility further includes a heavies removal unit, a condensationstorage tank, an LNG storage tank, and an LNG loading facility. Theheavies removal unit is configured to receive the dry purified naturalgas stream from the dehydration unit and to produce a liquid condensateproduct and a vapor product. The condensation storage tank is configuredto receive the liquid condensate product from the heavies removal unit,and to allow for the venting of boil off gas (BOG). The LNG storage tankis configured to receive and store LNG from the liquefaction unit, andto and to allow for the venting of BOG. The LNG loading facility isconfigured to receive LNG from the LNG storage tank and to transfer LNGto a marine vessel comprising a marine LNG storage tank. The LNG loadingfacility is further configured to allow for the venting of BOG. BOG fromat least one of the condensation storage tank, the LNG storage tank, andthe LNG loading facility is directable as feed to the steam reformer.

In a twenty-fourth aspect of the present disclosure, which may becombined with any other aspect listed herein unless specified otherwise,BOG from each of the condensation storage tank, the LNG storage tank,and the LNG loading facility is directable as feed to the steamreformer.

In a twenty-fifth aspect of the present disclosure, which may becombined with any other aspect listed herein unless specified otherwise,the LNG facility further includes a marine vent system adapted toreceive marine vessel tank gas from a marine LNG storage tank of amarine vessel, and to direct the marine vessel tank gas to feed any of:(a) a sequestration compression unit, (b) a fuel gas conditioning unit,and (c) a steam reformer. The marine vessel tank gas comprises BOG fromLNG, CO, CO2, N2 or mixtures thereof.

In a twenty-sixth aspect of the present disclosure, which may becombined with any other aspect listed herein unless specified otherwise,the seabed is located at a depth greater than about 3.0 kilometers belowsea level.

In a twenty-seventh aspect of the present disclosure, which may becombined with any other aspect listed herein unless specified otherwise,a liquefied natural gas (LNG) production facility includes aliquefaction unit and a sequestration compression unit. The liquefactionunit condenses natural gas vapor into liquefied natural gas. Theliquefaction unit may comprise at least one electrically drivenrefrigerant compressor. The sequestration compression unit is configuredto compress and convey at least one CO2-rich stream towards asequestration site, thereby reducing the overall emissions from the LNGfacility.

In a twenty-eighth aspect of the present disclosure, which may becombined with any other aspect listed herein unless specified otherwise,the sequestration site comprises an underground geological formationcomprising an at least partially depleted hydrocarbon reservoir.

In a twenty-ninth aspect of the present disclosure, which may becombined with any other aspect listed herein unless specified otherwise,the sequestration site comprises a region on top of a seabed, saidregion located at a depth greater than about 3.0 kilometers below sealevel.

In a thirtieth aspect of the present disclosure, which may be combinedwith any other aspect listed herein unless specified otherwise, thesequestration site comprises a region below a seabed.

In a thirty-first aspect of the present disclosure, which may becombined with any other aspect listed herein unless specified otherwise,the LNG facility further includes an acid gas removal unit configured toaccept raw feed natural gas and to generate an acid gas stream, a flashgas stream, and a purified natural gas stream. The acid gas stream isdirectable to the sequestration compression unit.

In a thirty-second aspect of the present disclosure, which may becombined with any other aspect listed herein unless specified otherwise,the flash gas stream is directable to the sequestration compressionunit.

In a thirty-third aspect of the present disclosure, which may becombined with any other aspect listed herein unless specified otherwise,the sequestration compression unit comprises an electric-drivencompressor.

In a thirty-fourth aspect of the present disclosure, which may becombined with any other aspect listed herein unless specified otherwise,the acid gas removal unit includes an amine absorber and liquid amineabsorbent for absorbing CO2.

In a thirty-fifth aspect of the present disclosure, which may becombined with any other aspect listed herein unless specified otherwise,the LNG facility further includes a dehydration unit including a solidadsorbent. The dehydration unit is configured to receive the purifiednatural gas stream from the acid gas removal unit and to provide a drypurified natural gas stream.

In a thirty-sixth aspect of the present disclosure, which may becombined with any other aspect listed herein unless specified otherwise,the LNG facility further includes a heavies removal unit, a condensationstorage tank, an LNG storage tank, and an LNG loading facility. Theheavies removal unit is configured to receive the dry purified naturalgas stream from the dehydration unit and to produce a liquid condensateproduct and a vapor product. The condensation storage tank is configuredto receive the liquid condensate product from the heavies removal unit,and to allow for the venting of boil off gas (BOG). The LNG storage tankis configured to receive and store LNG from the liquefaction unit, andto and to allow for the venting of BOG. The LNG loading facility isconfigured to receive LNG from the LNG storage tank and to transfer LNGto a marine vessel comprising a marine LNG storage tank. The LNG loadingfacility is further configured to allow for the venting of BOG. BOG fromat least one of the condensation storage tank and the LNG loadingfacility is directable as feed to the sequestration compression unit.

In a thirty-seventh aspect of the present disclosure, which may becombined with any other aspect listed herein unless specified otherwise,BOG from each of the condensation storage tank, the LNG storage tank,and the LNG loading facility is directable as feed to the liquefactionunit.

In a thirty-eighth aspect of the present disclosure, which may becombined with any other aspect listed herein unless specified otherwise,the LNG facility further includes a marine vent system adapted toreceive marine vessel tank gas from a marine LNG storage tank of amarine vessel, and to direct the marine vessel tank gas to feed any of:(a) the sequestration compression unit, (b) the liquefaction unit, and(c) one or more facility flares. The marine vessel tank gas comprisesBOG from LNG, CO, CO2, N2 or mixtures thereof.

In a thirty-ninth aspect of the present disclosure, which may becombined with any other aspect listed herein unless specified otherwise,the seabed is located at a depth greater than about 3.0 kilometers belowsea level.

In a fortieth aspect of the present disclosure, which may be combinedwith any other aspect listed herein unless specified otherwise, the acidgas removal unit includes a chilled ammonia process with an ammoniaabsorbent for absorbing CO2.

In a forty-first aspect of the present disclosure, which may be combinedwith any other aspect listed herein unless specified otherwise, a powerplant facility includes a gas turbine, at least one post-combustioncapture unit, and a sequestration compression unit. The gas turbine isconfigured to combust a hydrocarbon fuel enriched with at least 10percent hydrogen by volume. The at least one post-combustion captureunit generates a CO2-rich stream from the combustion products of the gasturbine. The sequestration compression unit is configured to compressand convey at least one CO2-rich stream from a post-combustion captureunit, towards a sequestration site.

In a forty-second aspect of the present disclosure, which may becombined with any other aspect listed herein unless specified otherwise,the power plant facility further includes an on-site hydrogen generationunit that provides hydrogen to the gas turbine.

In a forty-third aspect of the present disclosure, which may be combinedwith any other aspect listed herein unless specified otherwise, thehydrogen generation unit is a steam reformer.

In a forty-fourth aspect of the present disclosure, which may becombined with any other aspect listed herein unless specified otherwise,fuel to the gas turbine contains about 60 to 95 percent hydrogen byvolume.

In a forty-fifth aspect of the present disclosure, which may be combinedwith any other aspect listed herein unless specified otherwise, fuel tothe gas turbine contains about 75 to 90 percent hydrogen by volume.

In a forty-sixth aspect of the present disclosure, which may be combinedwith any other aspect listed herein unless specified otherwise, thesequestration site comprises an off-site underground geologicalformation comprising an at least partially depleted hydrocarbonreservoir.

In a forty-seventh aspect of the present disclosure, which may becombined with any other aspect listed herein unless specified otherwise,the hydrocarbon reservoir is only partially depleted. At least some ofthe transferred the CO2-rich stream is injected into the sequestrationsite to aid in enhanced oil recovery.

In a forty-eighth aspect of the present disclosure, which may becombined with any other aspect listed herein unless specified otherwise,the sequestration site comprises a pipeline for transporting a CO2-richstream.

In a forty-ninth aspect of the present disclosure, which may be combinedwith any other aspect listed herein unless specified otherwise, thepower plant facility further includes at least one capture unit thatconfigured to provide a CO2-rich stream from the products of the steamreformer.

In a fiftieth aspect of the present disclosure, which may be combinedwith any other aspect listed herein unless specified otherwise, thepower plant facility further includes a fuel conditioning skidconfigured to receive hydrogen from the hydrogen generation unit, and toreceive natural gas from a natural gas pipeline source, and to provide ablended fuel to the gas turbine.

In a fifty-first aspect of the present disclosure, which may be combinedwith any other aspect listed herein unless specified otherwise, thepower plant facility further includes a power generator that generateselectricity from power supplied by the gas turbine.

In a fifty-second aspect of the present disclosure, which may becombined with any other aspect listed herein unless specified otherwise,the power plant facility further includes a sequestration compressionunit configured to receive the CO2-rich stream from the capture unitconfigured to provide the CO2-rich stream from the products of the steamreformer, and configured to compress and convey at the CO2-rich streamtowards a sequestration site.

In a fifty-third aspect of the present disclosure, which may be combinedwith any other aspect listed herein unless specified otherwise, thesequestration compression unit comprises an electric-driven compressor.

In a fifty-fourth aspect of the present disclosure, which may becombined with any other aspect listed herein unless specified otherwise,the power plant facility further includes a waste heat recovery unitconfigured to pass combustion products from the gas turbine to apost-combustion capture unit.

In a fifty-fifth aspect of the present disclosure, which may be combinedwith any other aspect listed herein unless specified otherwise, thepower plant facility further includes a co-generation unit configured toreceive heat from the waste heat recovery unit and to provide power tothe power generator.

In a fifty-sixth aspect of the present disclosure, which may be combinedwith any other aspect listed herein unless specified otherwise, thesequestration compression unit comprises a compressor driven by steamfrom the waste heat recovery unit.

In a fifty-seventh aspect of the present disclosure, which may becombined with any other aspect listed herein unless specified otherwise,the post-combustion capture unit includes an amine absorber and liquidamine absorbent for absorbing CO2. Heat from the waste heat recoveryunit is directable to the post-combustion capture unit to provide heatfor regenerating the liquid amine absorbent.

In a fifty-eighth aspect of the present disclosure, which may becombined with any other aspect listed herein unless specified otherwise,the post-combustion capture unit includes a chilled ammonia process forabsorbing CO2. The steam reformer generates excess steam. The excesssteam is directable to the post-combustion capture unit to provide heatfor regenerating the ammonia absorbent.

In a fifty-ninth aspect of the present disclosure, which may be combinedwith any other aspect listed herein unless specified otherwise, thepower plant facility further includes at least one booster fanconfigured to receive the CO2-rich stream from the gas turbine and toconvey said flue gas stream towards the post-combustion capture unit.

In a sixtieth aspect of the present disclosure, which may be combinedwith any other aspect listed herein unless specified otherwise, a powerplant facility includes a gas turbine configured to combust a fuelcomprising at least about 90% hydrogen by volume

In a sixty-first aspect of the present disclosure, which may be combinedwith any other aspect listed herein unless specified otherwise, thepower plant facility further includes an on-site hydrogen generationunit that provides hydrogen to the gas turbine.

In a sixty-second aspect of the present disclosure, which may becombined with any other aspect listed herein unless specified otherwise,the hydrogen generation unit is a steam reformer.

In a sixty-third aspect of the present disclosure, which may be combinedwith any other aspect listed herein unless specified otherwise, thepower plant facility further includes a capture unit that configured toprovide a CO2-rich stream from the products of the steam reformer.

In a sixty-fourth aspect of the present disclosure, which may becombined with any other aspect listed herein unless specified otherwise,the power plant facility further includes a sequestration compressionunit configured to compress and convey the CO2-rich stream from thecapture unit, towards a sequestration site.

In a sixty-fifth aspect of the present disclosure, which may be combinedwith any other aspect listed herein unless specified otherwise, thesequestration site comprises an off-site underground geologicalformation comprising an at least partially depleted hydrocarbonreservoir.

In a sixty-sixth aspect of the present disclosure, which may be combinedwith any other aspect listed herein unless specified otherwise, thesequestration site comprises a railcar-mounted tank.

In a sixty-seventh aspect of the present disclosure, which may becombined with any other aspect listed herein unless specified otherwise,the sequestration site comprises a region on top of a seabed, saidregion located at a depth greater than about 3.0 kilometers below sealevel.

In a sixty-eighth aspect of the present disclosure, which may becombined with any other aspect listed herein unless specified otherwise,the sequestration site comprises a region below a seabed.

In a sixty-ninth aspect of the present disclosure, which may be combinedwith any other aspect listed herein unless specified otherwise, thepower plant facility further includes a fuel conditioning skidconfigured to receive hydrogen from the hydrogen generation unit andfrom an off-site hydrogen supply, and to provide fuel to the gasturbine.

In a seventieth aspect of the present disclosure, which may be combinedwith any other aspect listed herein unless specified otherwise, thepower plant facility further includes a power generator that generateselectricity from power supplied by the gas turbine.

In a seventy-first aspect of the present disclosure, which may becombined with any other aspect listed herein unless specified otherwise,the power plant facility further includes a waste heat recovery unitconfigured to receive combustion products from the gas turbine.

In a seventy-second aspect of the present disclosure, which may becombined with any other aspect listed herein unless specified otherwise,the power plant facility further includes a co-generation unitconfigured to receive heat from the waste heat recovery unit and providepower to the power generator.

In a seventy-third aspect of the present disclosure, which may becombined with any other aspect listed herein unless specified otherwise,the sequestration compression unit comprises a compressor driven bysteam from the waste heat recovery unit.

In a seventy-fourth aspect of the present disclosure, which may becombined with any other aspect listed herein unless specified otherwise,the sequestration compression unit comprises a compressor drive by steamfrom the on-site hydrogen generation unit.

In a seventy-fifth aspect of the present disclosure, which may becombined with any other aspect listed herein unless specified otherwise,the capture unit includes an amine absorber and liquid amine absorbentfor absorbing CO2. Heat from the waste heat recovery unit is directableto the capture unit to provide heat for regenerating the liquid amineabsorbent.

In a seventy-sixth aspect of the present disclosure, which may becombined with any other aspect listed herein unless specified otherwise,the capture unit includes a chilled ammonia process for absorbing CO2.The steam reformer generates excess steam. The excess steam isdirectable to the capture unit to provide heat for regenerating theammonia absorbent.

In a seventy-seventh aspect of the present disclosure, which may becombined with any other aspect listed herein unless specified otherwise,the seabed is located at a depth greater than about 3.0 kilometers belowsea level.

In a seventy-eighth aspect of the present disclosure, which may becombined with any other aspect listed herein unless specified otherwise,a liquefied natural gas (LNG) production facility includes aliquefaction unit, a gas turbine, a hydrogen generation unit, at leastone post-combustion capture unit, at least one capture unit, and asequestration compression unit. The liquefaction unit condenses naturalgas vapor into liquefied natural gas. The hydrogen generation unitincludes a steam reformer, whereby at least a portion of hydrogen formedin the hydrogen generation unit is combusted, along with hydrocarbons,as fuel in the gas turbine. The at least one post-combustion captureunit generates a CO2-rich stream from the combustion products of the gasturbine. The at least one capture unit generates a CO2-rich stream fromthe products of the steam reformer. The sequestration compression unitis configured to compress and convey at least one CO2-rich stream from acapture unit, towards a sequestration site, thereby reducing the overallemissions from the LNG facility.

In a seventy-ninth aspect of the present disclosure, which may becombined with any other aspect listed herein unless specified otherwise,the sequestration site comprises a region on top of a seabed, saidregion located at a depth greater than about 3.0 kilometers below sealevel.

In an eightieth aspect of the present disclosure, which may be combinedwith any other aspect listed herein unless specified otherwise, thesequestration site comprises a region below a seabed.

In an eighty-first aspect of the present disclosure, which may becombined with any other aspect listed herein unless specified otherwise,the seabed is located at a depth greater than about 3.0 kilometers belowsea level.

In an eighty-second aspect of the present disclosure, which may becombined with any other aspect listed herein unless specified otherwise,at least one of the capture units include a chilled ammonia process forabsorbing CO2. The steam reformer generates excess steam. The excesssteam is directable to the capture unit to provide heat for regeneratingthe ammonia absorbent.

In an eighty-third aspect of the present disclosure, which may becombined with any other aspect listed herein unless specified otherwise,the LNG production facility includes at least one booster fan configuredto receive a flue gas stream from the gas turbine and to convey saidflue gas stream towards the capture unit.

Additional features and advantages of the disclosed devices, systems,and methods are described in, and will be apparent from, the followingDetailed Description and the Figures. The features and advantagesdescribed herein are not all-inclusive and, in particular, manyadditional features and advantages will be apparent to one of ordinaryskill in the art in view of the figures and description. Also, anyparticular embodiment does not have to have all of the advantages listedherein. Moreover, it should be noted that the language used in thespecification has been principally selected for readability andinstructional purposes, and not to limit the scope of the inventivesubject matter.

BRIEF DESCRIPTION OF THE FIGURES

Understanding that the figures depict only typical embodiments of theinvention and are not to be considered to be limiting the scope of thepresent disclosure, the present disclosure is described and explainedwith additional specificity and detail through the use of theaccompanying figures. The figures are listed below.

FIG. 1 illustrates an exemplary schematic of a liquefied natural gasproduction facility.

FIG. 2 illustrates an exemplary schematic of a liquefied natural gasproduction facility, using at least about 90% hydrogen by volume as fuelto the gas turbine.

FIG. 3 illustrates an exemplary schematic of a liquefied natural gasproduction facility, with electric driven compressors.

FIG. 4 illustrates an exemplary schematic of a power plant with gasturbine post-combustion capture and hydrogen production.

FIG. 5 illustrates an exemplary schematic of a power plant with hydrogenproduction and carbon capture.

DETAILED DESCRIPTION OF EXAMPLE EMBODIMENTS

Although the following text sets forth a detailed description ofnumerous different embodiments, it should be understood that the legalscope of the invention is defined by the words of the claims set forthat the end of this patent. The detailed description is to be construedas exemplary only and does not describe every possible embodiment, asdescribing every possible embodiment would be impractical, if notimpossible. One of ordinary skill in the art could implement numerousalternate embodiments, which would still fall within the scope of theclaims. Unless a term is expressly defined herein using the sentence “Asused herein, the term ‘______’ is hereby defined to mean . . . ” or asimilar sentence, there is no intent to limit the meaning of that termbeyond its plain or ordinary meaning. To the extent that any term isreferred to in this patent in a manner consistent with a single meaning,that is done for sake of clarity only, and it is not intended that suchclaim term be limited to that single meaning. Finally, unless a claimelement is defined by reciting the word “means” and a function withoutthe recital of any structure, it is not intended that the scope of anyclaim element be interpreted based on the application of 35 U.S.C. §112(f).

Referring now to the figures, FIG. 1 illustrates an exemplary schematicof a liquefied natural gas production facility 100. The facility 100receives raw feed gas, such as natural gas, from a pipeline 102 (e.g., anatural gas pipeline).

Once received, the natural gas is sent from the pipeline 102 to an acidgas removal unit 104 within facility 100. Acid gas removal unit 104accepts this natural gas from pipeline 102, and generates one or more ofan acid gas stream, a flash gas stream, and a purified natural gasstream.

More specifically, acid gas removal unit 104 advantageously processesthe natural gas to remove various contaminants, such as mercury,hydrogen-sulfide, carbon dioxide, and the like. In a particularembodiment, the acid gas removal unit 104 treats incoming natural gas,in order to remove carbon dioxide from the natural gas stream. Forexample, acid gas removal unit 104 may implement an amine process, whichabsorbs the carbon dioxide in an amine absorber. In an embodiment, acidgas removal unit 104 includes an amine absorber and liquid amineabsorbent for absorbing carbon dioxide. The amine is then heated (e.g.,regenerated), to return to the absorber. The carbon dioxide rich stream(also referred to generally as an acid gas stream) is separated and sentdirectly to sequestration compression 130, described in greater detailherein. In an embodiment, acid gas removal includes a chilled ammoniaprocess for absorbing CO2, wherein excess steam is directable to acidgas removal to provide heat for regenerating ammonia absorbent.Advantageously, this acid gas stream is not sent to a thermal oxidizer;thus, the acid gas stream need not be combusted and released into theatmosphere via any thermal oxidation process. Similarly, acid gasremoval unit 104 directs the flash gas stream to at least one ofsequestration compression 130, fuel gas conditioning skid 118, andhydrogen production 120. When flash gas is sent to fuel gas conditioningskid 118, it can advantageously be used as fuel for the gas turbine 122;namely, fuel gas conditioning skid 118 may direct fuel gas to the gasturbine 122. When flash gas is sent to hydrogen production 120, it canadvantageously be used by a steam reformer as feedstock for thereformer.

Upon processing by acid gas removal unit 104, the purified natural gasstream, with the carbon dioxide removed, is sent to dehydration unit106.

More specifically, treated gas is then sent to a dehydration unit 106,which removes water from the gas. As illustrated by FIG. 1, thedehydration unit 106 is located downstream of the acid gas removal unit104. Thus, because the amine solution of the acid gas removal unit 104saturates the exiting feed gas with water, this water is removed in thedehydration unit 106. In an embodiment, dehydration unit 106 reduceswater content of feed gas to less than 0.5 ppmv, to prevent water freezeout in the downstream cryogenic processing within facility 100.

Dehydration unit 106 may include a solid adsorbent. In an embodiment,the dehydration unit 106 is based on a three-bed molecular sieve bedconfiguration: two beds operating in water adsorption mode, while thethird bed is being regenerated. During the adsorption process, the vaporis cooled, exits a drier feed gas filter coalescer, and passes downwardthrough regenerated molecular sieve driers. Each externally insulatedabsorber vessel contains 4 A molecular sieve adsorbent, to remove water.During the regeneration process, a slip stream of product gas (driedgas) is used for regeneration. The regeneration gas passes through adrier regeneration gas compressor and a flow control valve, before itenters the regeneration gas heat exchanger, which raises the gastemperature to 550° F. The dehydration regeneration gas is heated withhot oil. In an embodiment, the hot oil is heated from the waste heatrecovery units, such as waste heat recovery unit 124 described ingreater detail herein.

The gas, as a dry purified natural gas stream, is next sent to a heaviesremoval unit 108. In an embodiment, heavies removal unit 108 isconfigured to receive the dry purified natural gas stream from thedehydration unit 106 and subsequently produce both a liquid condensateproduct and a vapor product. Specifically, heavies removal unit 108separates condensate from gas, and sends condensate to a condensatestorage tank 109. Generally, the purpose of the heavies removal unit 106is to remove enough C5 and heavier components (including benzene) fromthe natural gas stream that has left the dehydration unit 106 to meetthe liquid natural gas (LNG) product specification and avoid theundesirable freezing of these components during liquefaction. In anembodiment, heavies removal unit 108 includes a series of pumps,exchangers, towers, compressors, and other related processing equipment,for separating heavy components.

The heavy components (e.g., liquid condensate product) are sent to acondensate storage tank, such as C5+ tank 109. Some of this condensatewill boil off, producing condensate boil off gas. This boil off gas maybe sent to at least one of fuel gas conditioning skid 118 or hydrogenproduction 120, as disclosed in greater detail herein. Advantageously,the boil off gas is not sent to a thermal oxidizer or other flare; thus,the boil off gas is not combusted and released into the atmosphere viaany thermal oxidation process.

After processing at the heavies removal unit 108, the gas is sent to aliquefaction unit 110. In an embodiment, liquefaction unit 110 is one ormore refrigeration units, compressors, and/or heat exchangers, whichconvert the gas into LNG via cooling and condensation. For example, thetemperature of the gas is lowered to approximately −260° F., thusnecessitating a phase change from gas to LNG. In an embodiment, the mainrefrigeration compressor(s) for liquefaction unit 110 is driven byeither a natural gas fired turbine or an electric motor. For example,liquefaction unit 110 may be powered, at least in part, via gas turbine122. In an embodiment, gas turbine 122 is mechanically coupled to atleast one compressor within liquefaction unit 110. In an alternativeembodiment, liquefaction unit 110 comprises at least oneelectrically-driven compressor, and gas turbine 122 drives an electricgenerator to provide electric power to at least one compressor withinthe liquefaction unit 110.

LNG is then sent to LNG storage 112. In an embodiment, LNG storage 112is one or more storage tanks, such as double walled tanks, which aretransportable. Once in a stored-state, LNG is constantly boiling off,producing additional boil off gas, which may be sent to at least one offuel gas conditioning skid 118 and hydrogen production 120, as disclosedin greater detail herein. Additionally or alternatively, boil off gascan be recompressed and sent back to the liquefaction unit 110.

Via LNG loading infrastructure 114, LNG is pumped out of the LNG storagetanks 112 and loaded into LNG vessels 116, via loading arms, cranes,forklifts, and other transportation means. In an particular embodiment,LNG vessel 116 is a seafaring ship with marine LNG storage tanks.Loading onto a ship typically produces additional boil off gas, whichmay be sent to at least one of fuel gas conditioning skid 118 andhydrogen production 120, as disclosed in greater detail herein.Advantageously, the boil off gas is not sent to a thermal oxidizer orother flare such as a marine flare. Facility 100 may further include amarine vent system, adapted to receive gas from a marine LNG storagetank on a vessel 116, and subsequently direct this ship vessel gas(e.g., boil off gas from LNG, carbon monoxide, carbon dioxide, nitrogen,or mixtures thereof) to any of post combustion capture facility 126,capture facility 128, sequestration compression 130, fuel gasconditioning skid 118, and hydrogen production 120 as appropriate.

As previously noted above, boil off gas is sent from one or more of acidgas removal unit 104, heavies removal unit 108, LNG storage 112, LNGloading 114, and ship 116 to one of at least fuel gas conditioning skid118 and hydrogen production 120.

Fuel gas conditioning skid 118 takes streams of natural gas, such asboil off gasses, and adjusts various physical conditions (e.g.,temperatures, pressures, blends, and the like) to ensure that the gassesare configured for optimal combustion in a gas turbine 122. In anembodiment, fuel gas conditioning skid 118 directs fuel gas to gasturbine 122. As previously noted, flash gas stream is directable to fuelgas conditioning skid 118 for use as fuel for gas turbine 122.

Advantageously, facility 100 further includes hydrogen production 120.In an embodiment, hydrogen production 120 is a steam reformer, such as amethane gas reformer, which is configured to generate hydrogen on-site.It should be appreciated that, in additional or alternative embodiments,hydrogen production 120 could be produced via other means, such as viaan electrolysis unit whereby water is split into hydrogen and oxygenthrough the use of electricity. Likewise, it should be appreciated that,in additional or alternative embodiments, hydrogen production 120 couldbe offsite, such as via an offsite supply of hydrogen, whereby hydrogenmay come into the LNG facility via pipeline, railcar, ship or otherconvenient means.

With that in mind, hydrogen production 120, such as via the steamreformer, allows for high temperature steam to react with methane, inthe presence of a catalyst, to produce hydrogen, carbon monoxide, andcarbon dioxide. With reference to FIG. 1, it should be appreciated thatboil off gas from each of condensation storage tank 109, LNG storage112, and LNG loading 114 are directable as feed to hydrogen production120. Additional processes can be incorporated with hydrogen production120, such as a water-gas shift reaction and/or pressure swingadsorption, to increase the yield of hydrogen.

Hydrogen may be provided to gas turbine 122 as fuel, for optimalcombustion. For example, the fuel provided to gas turbine 122 may be ahydrogen-enriched hydrocarbon fuel. In an embodiment, fuel provided togas turbine 122 contains at least 10 percent hydrogen by volume. In apreferred embodiment, fuel provided to gas turbine 122 contains about 60to less than 100 percent hydrogen by volume. In a more preferredembodiment, fuel provided to gas turbine 122 contains about 75 to 85percent hydrogen by volume. Excess hydrogen may be generated on-sitefrom the steam reformer. Such hydrogen may be stored in an on-sitestorage tank, and may be sent off-site for consumption by others, forexample, by way of pipeline, railcar, or truck-drawn trailer.

In an embodiment, facility 100 further includes one or more electricgenerators, whereby gas turbine 122 is coupled to the one or moreelectric generators; in this embodiment, facility 100 may further serveas a natural gas power generation facility.

In an embodiment, hydrogen production 120 generates excess steam, whichis directable to acid gas removal unit 104; this excess steam providesheat to acid gas removal unit 104 for regenerating liquid amineabsorbent. In an embodiment, hydrogen production 120 generates excesssteam, which is directable to dehydration unit 106; this excess steamprovides heat to dehydration unit 106 for regenerating solid adsorbent.In an embodiment, hydrogen production unit 120 generates excess steam,which is directable to drive a compressor. In a related embodiment,hydrogen production 120 generates excess steam, which is directable tosequestration compression 130; this excess steam drives a compressor atsequestration compression 130.

Once combusted, gas from the gas turbine 122 may pass to a waste heatrecovery unit 124. The waste heat recovery unit 124 uses heat generatedby a combustion process, such as via combustion in gas turbine 122, toheat up a heat medium (e.g., hot oil or steam). The heated medium isthen used in various processes throughout facility 100 where additionalheat is required (e.g., amine regeneration, dehydration regeneration,and the like).

For example, the waste heat recovery unit 124 may advantageouslycommunicate with one or more of acid gas removal unit 104, dehydrationunit 106, and heavies removal unit 108, to provide heat to thesecomponents. In an embodiment, waste heat recovery unit 124 communicateswith a cogeneration unit (not illustrated), which uses the waste heatfrom gas turbine 122 to generate steam that, in turn, rotates agenerator to produce electricity. The electricity can then be used inother parts of the facility 100 or, alternatively, be sent to theelectric grid.

After heat has been recovered at waste heat recovery unit 124, gaspasses to post combustion capture facility 126. In an embodiment, postcombustion capture facility 126 generates a carbon dioxide rich streamfrom the combustion products derived from the gas turbine 122.Specifically, post combustion capture facility 126 captures the productsof combustion, for example, using an amine process to absorb carbondioxide from the flue gas stream. Specifically, it should be appreciatedthat there are different types of amine depending on the relativeconcentrations of carbon dioxide in the flue gas stream. Natural gasfired turbines typically produce a relatively less concentrated carbondioxide stream (e.g., approximately less than 5%) as compared to anatural gas steam methane reformer 120 (e.g., approximately 25%) andthus would generally use a different mixture to absorb the carbondioxide. Other processes can additionally or alternatively include useof ammonia or other related materials. For example, capture may includea chilled ammonia process for absorbing CO2, wherein excess steam isdirectable to the capture unit to provide heat for regenerating ammoniaabsorbent. In an embodiment, one or more booster fans are configured toreceive a flue gas stream from the gas turbine 122 and to convey saidflue gas stream towards the post combustion capture facility 126.

Similar to gas passing from waste heat recovery unit 124 to postcombustion capture facility 126, it should be appreciated that gas fromhydrogen production 120 may pass directly to capture facility 128 (orthe same facility 126) and be processed as described above. Namely,capture facility 128 generates a carbon dioxide rich stream from theproducts of hydrogen production 120.

In an embodiment, post combustion capture facility 126 includes an amineabsorber and liquid amine absorbent for absorbing carbon dioxide. In arelated embodiment, hydrogen production 120 generates excess steam,which is directable to post combustion capture facility 126; this excesssteam provides heat to post combustion capture facility for regeneratingthe liquid amine absorbent.

After post combustion capture, gas passes to sequestration compressionunit 130. In other embodiments, the boil off gas streams from thecondensation storage tank 109, the LNG loading 114, and the ship 116,are sent to downstream of post combustion capture facility 126 tocombine with gas generated thereof before the combined gas passes tosequestration compression unit 130. In other embodiments, the boil offgas from the condensation storage tank 109, LNG storage 112, and/or theship 116, is directly sent to the sequestration compression unit 130.

It is understood that natural gas pipelines are often make use ofvarious pigging operations. For example, pig devices may be used innatural gas pipelines to clean the pipeline, and so-called smart pigsmay be used to inspect the pipeline, and for other purposes. Piginsertion and especially pig recovery systems, located within or nearfacility 100, may be significant sources of emissions. Such emissions,typically of natural gas, may often be combusted in a flare or simplyvented to the atmosphere. In an embodiment, emissions from pig recoverysystem 133 may be directed as feed to hydrogen production 120, ordirected to the fuel conditioning skid 118, or directed to sequestrationcompression 130.

Sequestration compression unit 130 includes one or more knockout drumsfor collecting any remaining liquid in the gas stream. Sequestrationcompression unit 130 further includes at least one compressor,configured to compress the carbon dioxide rich stream, which may be thensent to a pipeline for off-site sequestration 132. By sending the carbondioxide rich stream to some form of sequestration, overall greenhousegas emissions from facility 100 are reduced. Other forms ofsequestration (not shown in FIG. 1) may be implemented, including forexample sending the CO2 rich gas to an on-site or off-site storage tank,to a tank mounted on a rail car, or a tank mounted on a truck-drawntrailer. After compression, the sequestered CO2 rich gas mayadvantageously be sold for a number of well-known applications and uses.

In an embodiment, sequestration compression unit 130 includes acompressor that is driven by steam generated from a steam reformerduring hydrogen production 120. In a related embodiment, the compressoris driven by a hydrogen turbine configured to be driven by excesshydrogen, derived from the steam reformer during hydrogen production120. In another embodiment, sequestration compression unit 130 includesa compressor that is driven by gas turbine 122. In yet anotherembodiment, sequestration compression unit 130 includes a compressorthat is driven by an electric motor. Liquids from the knockout drumswithin sequestration compression unit 130 are sent back to C5+ storagetank 109.

As previously noted, sequestration compression unit 130 sends the carbondioxide rich stream away from facility 100 for off-site sequestration132. In an embodiment, sequestration 132 is an underground geologicalformation that includes at least a partially depleted hydrocarbonreservoir. In a related embodiment, at least some of the transferredcarbon dioxide rich stream is injectable into the hydrocarbon reservoir,to aid in enhanced oil recovery. In another example, the sequestrationsite is a region on top of a seabed, at a depth greater than threekilometers below sea level. In yet another example, the sequestrationsite is a region below a seabed. In yet another example, thesequestration site is a region below a seabed, wherein the seabed islocated at a depth greater than about 3.0 kilometers below sea level.

FIG. 2 illustrates an exemplary schematic of a liquefied natural gasproduction facility 200, using at least about 90% hydrogen by volume asfuel to the gas turbine. The facility 200 receives raw feed gas, such asnatural gas, from a pipeline 202 (e.g., a natural gas pipeline).

Once received, the natural gas is sent from the pipeline 202 to an acidgas removal unit 204 within facility 200. Acid gas removal unit 204accepts this natural gas from pipeline 202, and generates one or more ofan acid gas stream, a flash gas stream, and a purified natural gasstream.

More specifically, acid gas removal unit 204 advantageously processesthe natural gas to remove various contaminants, such as mercury,hydrogen-sulfide, carbon dioxide, and the like. In a particularembodiment, the acid gas removal unit 204 treats incoming natural gas,in order to remove carbon dioxide from the natural gas stream. Forexample, acid gas removal unit 204 may implement an amine process, whichabsorbs the carbon dioxide in an amine absorber. In an embodiment, acidgas removal unit 204 includes an amine absorber and liquid amineabsorbent for absorbing carbon dioxide. The amine is then heated (e.g.,regenerated), to return to the absorber. The carbon dioxide rich stream(also referred to generally as an acid gas stream) is separated and sentdirectly to sequestration compression 230, described in greater detailherein. In an embodiment, acid gas removal includes a chilled ammoniaprocess for absorbing CO2, wherein excess steam is directable to acidgas removal to provide heat for regenerating ammonia absorbent.Advantageously, this acid gas stream is not sent to a thermal oxidizer;thus, the acid gas stream need not be combusted and released into theatmosphere via any thermal oxidation process. Similarly, acid gasremoval unit 204 directs the flash gas stream to at least one ofsequestration compression 230, and hydrogen production 220. When flashgas is sent to hydrogen production 220, it can advantageously be used bya steam reformer as feedstock for the reformer.

Upon processing by acid gas removal unit 204, the purified natural gasstream, with the carbon dioxide removed, is sent to dehydration unit206.

More specifically, treated gas is then sent to a dehydration unit 206,which removes water from the gas. As illustrated by FIG. 2, thedehydration unit 206 is located downstream of the acid gas removal unit204. Thus, because the amine solution of the acid gas removal unit 204saturates the exiting feed gas with water, this water is removed in thedehydration unit 206. In an embodiment, dehydration unit 206 reduceswater content of feed gas to less than 0.5 ppmv, to prevent water freezeout in the downstream cryogenic processing within facility 200.

Dehydration unit 206 may include a solid adsorbent. In an embodiment,the dehydration unit 206 is based on a three-bed molecular sieve bedconfiguration: two beds operating in water adsorption mode, while thethird bed is being regenerated. During the adsorption process, the vaporis cooled, exits a drier feed gas filter coalescer, and passes downwardthrough regenerated molecular sieve driers. Each externally insulatedabsorber vessel contains 4 A molecular sieve adsorbent, to remove water.During the regeneration process, a slip stream of product gas (driedgas) is used for regeneration. The regeneration gas passes through adrier regeneration gas compressor and a flow control valve, before itenters the regeneration gas heat exchanger, which raises the gastemperature to 550° F. The dehydration regeneration gas is heated withhot oil. In an embodiment, the hot oil is heated from the waste heatrecovery units, such as waste heat recovery unit 224 described ingreater detail herein.

The gas, as a dry purified natural gas stream, is next sent to a heaviesremoval unit 208. In an embodiment, heavies removal unit 208 isconfigured to receive the dry purified natural gas stream from thedehydration unit 206 and subsequently produce both a liquid condensateproduct and a vapor product. Specifically, heavies removal unit 208separates condensate from gas, and sends condensate to a condensatestorage tank 209. Generally, the purpose of the heavies removal unit 206is to remove enough C5 and heavier components (including benzene) fromthe natural gas stream that has left the dehydration unit 206 to meetthe liquid natural gas (LNG) product specification and avoid theundesirable freezing of these components during liquefaction. In anembodiment, heavies removal unit 208 includes a series of pumps,exchangers, towers, compressors, and other related processing equipment,for separating heavy components.

The heavy components (e.g., liquid condensate product) are sent to acondensate storage tank, such as C5+ tank 209. Some of this condensatewill boil off, producing condensate boil off gas. This boil off gas maybe sent to hydrogen production 220, as disclosed in greater detailherein. Advantageously, the boil off gas is not sent to a thermaloxidizer or other flare; thus, the boil off gas is not combusted andreleased into the atmosphere via any thermal oxidation process.

After processing at the heavies removal unit 208, the gas is sent to aliquefaction unit 210. In an embodiment, liquefaction unit 210 is one ormore refrigeration units, compressors, and/or heat exchangers, whichconvert the gas into LNG via cooling and condensation. For example, thetemperature of the gas is lowered to approximately −260° F., thusnecessitating a phase change from gas to LNG. In an embodiment, the mainrefrigeration compressor(s) for liquefaction unit 210 is driven by a gasfired turbine. For example, liquefaction unit 210 may be powered, atleast in part, via gas turbine 222. As with the embodiment in FIG. 1described above, for example, liquefaction unit 210 may be powered, atleast in part, via gas turbine 222. In an embodiment, gas turbine 222 ismechanically coupled to at least one compressor within liquefaction unit210. In an alternative embodiment, liquefaction unit 210 comprises atleast one electrically-driven compressor, and gas turbine 222 drives anelectric generator to provide electric power to at least one compressorwithin the liquefaction unit 210.

LNG is then sent to LNG storage 212. In an embodiment, LNG storage 212is one or more storage tanks, such as double walled tanks, which aretransportable. Once in a stored-state, LNG is constantly boiling off,producing additional boil off gas, which may be sent to hydrogenproduction 220, as disclosed in greater detail herein. Additionally oralternatively, boil off gas can be recompressed and sent back to theliquefaction unit 210.

Via LNG loading infrastructure 214, LNG is pumped out of the LNG storagetanks 212 and loaded into LNG vessels 216, via loading arms, cranes,forklifts, and other transportation means. In an particular embodiment,LNG vessel 216 is a seafaring ship with marine LNG storage tanks.Loading onto a ship typically produces additional boil off gas, whichmay be sent to hydrogen production 220, as disclosed in greater detailherein. Advantageously, the boil off gas is not sent to a thermaloxidizer or other flare such as a marine flare. Facility 200 may furtherinclude a marine vent system, adapted to receive gas from a marine LNGstorage tank on a vessel 216, and subsequently direct this ship vesselgas (e.g., boil off gas from LNG, carbon monoxide, carbon dioxide,nitrogen, or mixtures thereof) to any of capture facility 228,sequestration compression 230, fuel gas conditioning skid 218, andhydrogen production 220 as appropriate.

As previously noted above, boil off gas is sent from one or more heaviesremoval unit 208, LNG storage 212, LNG loading 214, and ship 216 to oneof at least fuel gas conditioning skid 218 and hydrogen production 220.

Fuel gas conditioning skid 218 takes streams of natural gas, such asboil off gasses, and adjusts various physical conditions (e.g.,temperatures, pressures, blends, and the like) to ensure that the gassesare configured for optimal combustion in a gas turbine 222. In anembodiment, fuel gas conditioning skid 218 directs fuel gas to gasturbine 222. As previously noted, flash gas stream is directable to fuelgas conditioning skid 218 for use as fuel for gas turbine 222.

Advantageously, facility 200 further includes hydrogen production 220.In an embodiment, hydrogen production 220 is a steam reformer, such as amethane gas reformer, which is configured to generate hydrogen on-site.It should be appreciated that, in additional or alternative embodiments,hydrogen production 220 could be produced via other means, such as viaan electrolysis unit whereby water is split into hydrogen and oxygenthrough the use of electricity. Likewise, it should be appreciated that,in additional or alternative embodiments, hydrogen production 220 couldbe offsite, such as via an offsite supply of hydrogen, whereby hydrogenmay come into the LNG facility via pipeline, railcar, ship or otherconvenient means. In an embodiment, facility 200 uses at least about 90%hydrogen, by volume, as fuel to the gas turbine 222. In a relatedembodiment, the remaining balance (i.e., up to about 10% by volume) ofthe fuel gas stream may also include CO2, N2 and/or oxygen in anyproportions.

With that in mind, hydrogen production 220, such as via the steamreformer, allows for high temperature steam to react with methane, inthe presence of a catalyst, to produce hydrogen, carbon monoxide, andcarbon dioxide. With reference to FIG. 2, it should be appreciated thatboil off gas from each of condensation storage tank 209, LNG storage212, and LNG loading 214 are directable as feed to hydrogen production220. Additional processes can be incorporated with hydrogen production220, such as a water-gas shift reaction and/or pressure swingadsorption, to increase the yield of hydrogen.

Hydrogen may be provided to gas turbine 222 as fuel, for optimalcombustion. For example, the fuel provided to gas turbine 222 may be ahydrogen-enriched hydrocarbon fuel. In an embodiment, fuel provided togas turbine 222 contains at least 10 percent hydrogen by volume. In apreferred embodiment, fuel provided to gas turbine 222 contains about 60to less than 100 percent hydrogen by volume. In a more preferredembodiment, fuel provided to gas turbine 222 contains about 75 to 85percent hydrogen by volume. In a further more preferred embodiment, fuelprovided to gas turbine 222 contains at least about 90% hydrogen byvolume. Excess hydrogen may be generated on-site from the steamreformer. Such hydrogen may be stored in an on-site storage tank, andmay be sent off-site for consumption by others, for example, by way ofpipeline, railcar, or truck-drawn trailer.

In an embodiment, facility 200 further includes one or more electricgenerators, whereby gas turbine 222 is coupled to the one or moreelectric generators; in this embodiment, facility 200 may further serveas a natural gas power generation facility.

In an embodiment, hydrogen production 220 generates excess steam, whichis directable to acid gas removal unit 204; this excess steam providesheat to acid gas removal unit 204 for regenerating liquid amineabsorbent. In an embodiment, hydrogen production 220 generates excesssteam, which is directable to dehydration unit 206; this excess steamprovides heat to dehydration unit 206 for regenerating solid adsorbent.In an embodiment, hydrogen production unit 220 generates excess steam,which is directable to drive a compressor. In a related embodiment,hydrogen production 220 generates excess steam, which is directable tosequestration compression 230; this excess steam drives a compressor atsequestration compression 230.

Once combusted, gas from the gas turbine 222 may pass to a waste heatrecovery unit 224. The waste heat recovery unit 224 uses heat generatedby a combustion process, such as via combustion in gas turbine 222, toheat up a heat medium (e.g., hot oil or steam). The heated medium isthen used in various processes throughout facility 200 where additionalheat is required (e.g., amine regeneration, dehydration regeneration,and the like).

For example, the waste heat recovery unit 224 may advantageouslycommunicate with one or more of acid gas removal unit 204, dehydrationunit 206, and heavies removal unit 208, to provide heat to thesecomponents. In an embodiment, waste heat recovery unit 224 communicateswith a cogeneration unit (not illustrated), which uses the waste heatfrom gas turbine 222 to generate steam that, in turn, rotates agenerator to produce electricity. The electricity can then be used inother parts of the facility 200 or, alternatively, be sent to theelectric grid. Combusted gas from the gas turbine 222 may eventually bevented to the atmosphere. Since the combustion gas from the gas turbine222 is relatively low in carbon dioxide and other greenhouse gases, forexample, as low as about 3.0% by volume, or more preferably as low asabout 1.5% by volume, this stream of combusted gas need not be furthertreated in a post-combustion capture unit to remove carbon dioxide, andthe overall greenhouse gas emissions from facility 200 will not begreatly increased by such venting of combustion gases to the atmosphere.

Meanwhile, a carbon dioxide containing gas from hydrogen production 220passes to capture facility 228. In an embodiment, capture facility 228generates a carbon dioxide rich stream from the products derived fromhydrogen production 220. Specifically, capture facility 228 captures,for example, using an amine process to absorb carbon dioxide from theflue gas stream. Specifically, it should be appreciated that there aredifferent types of amine depending on the relative concentrations ofcarbon dioxide in the flue gas stream. Natural gas fired turbinestypically produce a relatively less concentrated carbon dioxide stream(e.g., approximately less than 5%) as compared to a natural gas steammethane reformer 220 (e.g., approximately 25%) and thus would generallyuse a different mixture to absorb the carbon dioxide. Other processescan additionally or alternatively include use of ammonia or otherrelated materials. For example, capture may include a chilled ammoniaprocess for absorbing CO2, wherein excess steam is directable to thecapture unit to provide heat for regenerating ammonia absorbent.

In an embodiment, capture facility 228 includes an amine absorber andliquid amine absorbent for absorbing carbon dioxide. In a relatedembodiment, hydrogen production 220 generates excess steam, which isdirectable to capture facility 228; this excess steam provides heat tocapture facility for regenerating the liquid amine absorbent.

After capture, gas passes to sequestration compression unit 230. Morespecifically, sequestration compression unit 230 includes one or moreknockout drums for collecting any remaining liquid in the gas stream.Sequestration compression unit 230 further includes at least onecompressor, configured to compress the carbon dioxide rich stream, whichmay be then sent to a pipeline for off-site sequestration 232. Bysending the carbon dioxide rich stream to some form of sequestration,overall greenhouse gas emissions from facility 200 are reduced. Otherforms of sequestration (not shown in FIG. 2) may be implemented,including for example sending the CO2 rich gas to an on-site or off-sitestorage tank, to a tank mounted on a rail car, or a tank mounted on atruck-drawn trailer. After compression, the sequestered CO2 rich gas mayadvantageously be sold for a number of well-known applications and uses.

In an embodiment, sequestration compression unit 230 includes acompressor that is driven by steam generated from a steam reformerduring hydrogen production 220. In a related embodiment, the compressoris driven by a hydrogen turbine configured to be driven by excesshydrogen, derived from the steam reformer during hydrogen production220. In another embodiment, sequestration compression unit 230 includesa compressor that is driven by gas turbine 222. In yet anotherembodiment, sequestration compression unit 230 includes a compressorthat is driven by an electric motor. Liquids from the knockout drumswithin sequestration compression unit 230 are sent back to C5+ storagetank 209.

In other embodiments, the boil off gas from the condensation storagetank 209, the LNG loading 214, and/or the ship 216, is directly sent tothe sequestration compression unit 130.

As with the LNG facility 100 described above, natural gas pipeline 202providing natural gas to LNG facility 200 may have associated with itone or more pig recovery systems 233 or other pig-related systems, whichmay be significant sources of emissions that would typically be flaredand/or vented to the atmosphere. In an embodiment, emissions from pigrecovery system 233 are directed as feed to hydrogen production 220,directed to the fuel conditioning skid 218, and/or directed tosequestration compression 230.

As previously noted, sequestration compression unit 230 sends the carbondioxide rich stream away from facility 200 for off-site sequestration232. In an embodiment, sequestration 232 is an underground geologicalformation that includes at least a partially depleted hydrocarbonreservoir. In a related embodiment, at least some of the transferredcarbon dioxide rich stream is injectable into the hydrocarbon reservoir,to aid in enhanced oil recovery. In another example, the sequestrationsite is a region on top of a seabed, at a depth greater than threekilometers below sea level. In yet another example, the sequestrationsite is a region below a seabed, or other dispositions as disclosedherein.

FIG. 3 illustrates an exemplary schematic of a liquefied natural gasproduction facility 300, with electric driven compressors. The facility300 receives raw feed gas, such as natural gas, from a pipeline 302(e.g., a natural gas pipeline).

Once received, the natural gas is sent from the pipeline 302 to an acidgas removal unit 304 within facility 300. Acid gas removal unit 304 issimilar to acid gas removal units 104, 204 (discussed above), acceptingthis natural gas from pipeline 302, and generating one or more of anacid gas stream, a flash gas stream, and a purified natural gas stream.The carbon dioxide rich acid gas stream is separated and sent directlyto sequestration compression 330, described in greater detail herein.

Upon processing by acid gas removal unit 304, the purified natural gasstream, with the carbon dioxide removed, is sent to dehydration unit306.

More specifically, treated gas is then sent to a dehydration unit 306,which removes water from the gas. As illustrated by FIG. 3, thedehydration unit 306 is located downstream of the acid gas removal unit304. Thus, because the amine solution of the acid gas removal unit 304saturates the exiting feed gas with water, this water is removed in thedehydration unit 306. In an embodiment, dehydration unit 106 reduceswater content of feed gas to less than 0.5 ppmv, to prevent water freezeout in the downstream cryogenic processing within facility 300.Dehydration unit 306 may include a solid adsorbent, similar todehydration units 106, 206.

The gas, as a dry purified natural gas stream, is next sent to a heaviesremoval unit 308. In an embodiment, heavies removal unit 308 isconfigured to receive the dry purified natural gas stream from thedehydration unit 306 and subsequently produce both a liquid condensateproduct and a vapor product. Specifically, heavies removal unit 308separates condensate from gas, and sends condensate to a condensatestorage tank 309. Generally, the purpose of the heavies removal unit 306is to remove enough C5 and heavier components (including benzene) fromthe natural gas stream that has left the dehydration unit 306 to meetthe liquid natural gas (LNG) product specification and avoid theundesirable freezing of these components during liquefaction. In anembodiment, heavies removal unit 308 includes a series of pumps,exchangers, towers, compressors, and other related processing equipment,for separating heavy components.

The heavy components (e.g., liquid condensate product) are sent to acondensate storage tank, such as C5+ tank 309. Some of this condensatewill boil off, producing condensate boil off gas. In a traditionalliquefied natural gas production facility, the boil off gas from thecondensate storage tank, or the heavies removal unit may be sent to athermal oxidizer to be combusted and then released to the atmosphere.However, in an embodiment, this boil off gas is sent to sequestrationcompression 330, as disclosed in greater detail herein. Advantageously,the boil off gas is not sent to a thermal oxidizer or other flare; thus,the boil off gas is not combusted and released into the atmosphere viaany thermal oxidation process.

After processing at the heavies removal unit 308, the gas is sent to aliquefaction unit 310. The boil off gas from the condensate storage tank309 and the heavies removal unit 308, may alternatively be sent to theliquefaction unit 310.

In an embodiment, liquefaction unit 310 is one or more refrigerationunits, compressors, and/or heat exchangers, which convert the gas intoLNG via cooling and condensation. For example, the temperature of thegas is lowered to approximately −260° F., thus necessitating a phasechange from gas to LNG. In an embodiment, the main refrigerationcompressor(s) for liquefaction unit 310 is driven by an electric motorpowered by the electric grid 322.

LNG is then sent to LNG storage 312. In an embodiment, LNG storage 312is one or more storage tanks, such as double walled tanks, which aretransportable. Once in a stored-state, LNG is constantly boiling off,producing additional boil off gas, which may be recompressed and sentback to the liquefaction unit 310.

Via LNG loading infrastructure 314, LNG is pumped out of the LNG storagetanks 312 and loaded into LNG vessels 316, via loading arms, cranes,forklifts, and other transportation means. In a particular embodiment,LNG vessel 316 is a seafaring ship with marine LNG storage tanks.Loading onto a ship typically produces additional boil off gas, whichmay be recompressed and sent back to the liquefaction unit 310.Advantageously, the boil off gas is not sent to a thermal oxidizer orother flare such as a marine flare. Facility 300 may further include amarine vent system, adapted to receive gas from a marine LNG storagetank on a vessel 316, and subsequently direct this ship vessel gas(e.g., boil off gas from LNG, carbon monoxide, carbon dioxide, nitrogen,or mixtures thereof) to recompression and back to liquefaction unit 310.Traditionally, the boil off gas from the LNG storage tanks 312, loadinginfrastructure 314 and LNG vessels 316, be sent to flare or ship ventsystem and released to the atmosphere.

However, in certain embodiments, such boil off gas can be passeddirectly to sequestration compression unit 330. That is, the boil offgas from the condensation storage tank 309, the LNG loading 314, and/orthe vessel 316 can be passed directly to the sequestration compressionunit 330.

Sequestration compression unit 330 includes one or more knockout drumsfor collecting any remaining liquid in the gas stream. Sequestrationcompression unit 330 further includes at least one compressor,configured to compress the carbon dioxide rich stream, which may be thensent to a pipeline for off-site sequestration 332. By sending the carbondioxide rich stream to some form of sequestration, overall greenhousegas emissions from facility 300 are reduced. Other forms ofsequestration (not shown in FIG. 3) may be implemented, including forexample sending the CO2 rich gas to an on-site or off-site storage tank,to a tank mounted on a rail car, or a tank mounted on a truck-drawntrailer. After compression, the sequestered CO2 rich gas mayadvantageously be sold for a number of well-known applications and uses.

In an embodiment, sequestration compression unit 330 includes acompressor that is driven by steam or, alternatively, driven by powervia electric grid 322. In yet another embodiment, sequestrationcompression unit 330 includes a compressor that is driven by an electricmotor. Liquids from the knockout drums within sequestration compressionunit 330 are sent back to C5+ storage tank 309.

As with the LNG facilities 100 and 200 described above, natural gaspipeline 302 providing natural gas to LNG facility 300 may haveassociated with it one or more pig recovery systems 333 or otherpig-related systems, which may be significant sources of emissions thatwould typically be flared and/or vented to the atmosphere. In anembodiment, emissions from pig recovery system 333 are directed tosequestration compression 330.

As previously noted, sequestration compression unit 330 sends the carbondioxide rich stream away from facility 300 for off-site sequestration332. In an embodiment, sequestration 332 is an underground geologicalformation that includes at least a partially depleted hydrocarbonreservoir. In a related embodiment, at least some of the transferredcarbon dioxide rich stream is injectable into the hydrocarbon reservoir,to aid in enhanced oil recovery. In another example, the sequestrationsite is a region on top of a seabed, at a depth greater than threekilometers below sea level. In yet another example, the sequestrationsite is a region below a seabed, or other dispositions as disclosedherein.

FIG. 4 illustrates an exemplary schematic of a power plant 400 with gasturbine post-combustion capture and hydrogen production. Specifically,power plant 400 receives raw feed gas, such as natural gas, from apipeline 402 (e.g., a natural gas pipeline).

As with the LNG facilities described above, natural gas pipeline 402providing natural gas to facility 400 may have associated with it one ormore pig recovery systems 433 or other pig-related systems, which may besignificant sources of emissions that would typically be flared and/orvented to the atmosphere. In an embodiment, emissions from pig recoverysystem 433 are directed to facility 400 for use as natural gasfeedstock.

Once received, the natural gas is sent from the pipeline 402 to a numberof different locations, including pretreatment 404, fuel gasconditioning skid 406, and hydrogen production 408. More specifically,gas is sent from pipeline 402 to pretreatment 404, to be treated priorto being sent to fuel gas conditioning skid 406. At pretreatment 404,the gas may be processed to remove various contaminants, such asmercury, hydrogen-sulfide, carbon dioxide, and the like.

If gas does not need pretreatment, it may pass directly to fuel gasconditioning skid 406. When gas is sent to fuel gas conditioning skid406, it can advantageously be used as fuel for the gas turbine 418;namely, fuel gas conditioning skid 406 may direct fuel gas to the gasturbine 418. Fuel gas conditioning skid 406 takes streams of natural gasand adjusts various physical conditions (e.g., temperatures, pressures,blends, and the like) to ensure that the gasses are configured foroptimal combustion in a gas turbine 418.

Similarly, when gas is sent to hydrogen production 408, it canadvantageously be used by a steam reformer as feedstock for thereformer. Specifically, in an embodiment, hydrogen production 408 is asteam reformer, such as a methane gas reformer, which is configured togenerate hydrogen on-site. It should be appreciated that, in additionalor alternative embodiments, hydrogen production 408 could be producedvia other means, such as via an electrolysis unit whereby water is splitinto hydrogen and oxygen through the use of electricity. Likewise, itshould be appreciated that, in additional or alternative embodiments,hydrogen production 408 could be offsite, such as via an offsite supplyof hydrogen, whereby hydrogen may come into the power generationfacility via pipeline, railcar, ship or other convenient means.

With that in mind, hydrogen production 408, such as via the steamreformer, allows for high temperature steam to react with methane, inthe presence of a catalyst, to produce hydrogen, carbon monoxide, andcarbon dioxide. Additional processes can be incorporated with hydrogenproduction 408, such as a water-gas shift reaction and/or pressure swingadsorption, to increase the yield of hydrogen.

Hydrogen may be provided to gas turbine 418 as fuel (or to the fuel gasconditioning skid 406 prior to the gas turbine 418), for optimalcombustion. It should be appreciated that additional hydrogen may beprovided, beyond the supply from hydrogen production 408, such as fromoffsite hydrogen supply 416.

Continuing on with respect to hydrogen production 408, for example, thefuel provided to gas turbine 418 may be a hydrogen-enriched hydrocarbonfuel. In an embodiment, fuel provided to gas turbine 418 contains atleast 10 percent hydrogen by volume. In a preferred embodiment, fuelprovided to gas turbine 418 contains about 60 to less than 100 percenthydrogen by volume. In a more preferred embodiment, fuel provided to gasturbine 418 contains about 75 to 85 percent hydrogen by volume. Excesshydrogen may be generated on-site from the steam reformer. Such hydrogenmay be stored in an on-site storage tank, and may be sent forconsumption by others such as onsite/offsite hydrogen users 410 withinplant 400. Moreover, excess steam from hydrogen production 408 may bedirected to various steam user 412, such as those described above. Acarbon dioxide containing stream from hydrogen production 408 may alsopass to capture facility 414, which is similar to the capture facilities128, 228 (discussed above). In an embodiment, capture facility 414generates a carbon dioxide rich stream from the products derived fromhydrogen production 408, and passes the carbon dioxide rich stream tosequestration compression 430.

In an embodiment, plant 400 further includes one or more powergenerators 420, such as electric generators, whereby gas turbine 418 iscoupled to the one or more electric generators 420; in this embodiment,facility 400 functions as a natural gas power generation facility.Namely, power from gas turbine 418 is transferred to power generator420, which delivers this electricity to an external electric grid 422.

Once combusted, gas from the gas turbine 418 may pass to a waste heatrecovery unit 424. The waste heat recovery unit 424 uses heat generatedby a combustion process, such as via combustion in gas turbine 418, toheat up a heat medium (e.g., hot oil or steam). The heated medium isthen used in various processes throughout facility 400 where additionalheat is required (e.g., amine regeneration, dehydration regeneration,and the like for pretreatment 400).

In an embodiment, waste heat recovery unit 424 communicates with acogeneration unit 428, which uses the waste heat from gas turbine 418 togenerate steam that, in turn, rotates a generator, such as powergenerator 420 or another generator. The electricity can then be used inother parts of the facility 400 or, alternatively, be sent to theelectric grid 422.

After heat has been recovered at waste heat recovery unit 424, gaspasses to post combustion capture facility 426. In an embodiment, postcombustion capture facility 426 generates a carbon dioxide rich streamfrom the combustion products derived from the gas turbine 418.Specifically, post combustion capture facility 426 captures the productsof combustion, for example, using an amine process to absorb carbondioxide from the flue gas stream. Specifically, it should be appreciatedthat there are different types of amine depending on the relativeconcentrations of carbon dioxide in the flue gas stream. Natural gasfired turbines typically produce a relatively less concentrated carbondioxide stream (e.g., approximately less than 5%) as compared to anatural gas steam methane reformer 408 (e.g., approximately 25%) andthus would generally use a different mixture to absorb the carbondioxide. Other processes can additionally or alternatively include useof ammonia or other related materials. For example, capture may includea chilled ammonia process for absorbing CO2, wherein excess steam isdirectable to the capture unit to provide heat for regenerating ammoniaabsorbent. In an embodiment, one or more booster fans are configured toreceive a flue gas stream from the gas turbine 418 and to convey saidflue gas stream towards the post combustion capture facility 426.

Similar to gas passing from waste heat recovery unit 424 to postcombustion capture facility 426, it should be appreciated that carbondioxide containing gas from hydrogen production 408 may pass directly topost combustion capture facility 426 and be processed as describedabove. Namely, post combustion capture facility 426 generates a carbondioxide rich stream from the products of hydrogen production 408.

In an embodiment, post combustion capture facility 426 includes an amineabsorber and liquid amine absorbent for absorbing carbon dioxide. In arelated embodiment, hydrogen production 408 generates excess steam,which is directable to post combustion capture facility 426; this excesssteam provides heat to post combustion capture facility for regeneratingthe liquid amine absorbent.

After post combustion capture, gas passes to sequestration compressionunit 430. More specifically, sequestration compression unit 430 includesone or more knockout drums for collecting any remaining liquid in thegas stream. Sequestration compression unit 430 further includes at leastone compressor, configured to compress the carbon dioxide rich stream,which may be then sent to a pipeline for off-site sequestration 432. Bysending the carbon dioxide rich stream to some form of sequestration,overall greenhouse gas emissions from facility 400 are reduced. Otherforms of sequestration (not shown in FIG. 4) may be implemented,including for example sending the CO2 rich gas to an on-site or off-sitestorage tank, to a tank mounted on a rail car, or a tank mounted on atruck-drawn trailer. After compression, the sequestered CO2 rich gas mayadvantageously be sold for a number of well-known applications and uses.

In an embodiment, sequestration compression unit 430 includes acompressor that is driven by steam generated from a steam reformerduring hydrogen production 408. In a related embodiment, the compressoris driven by a hydrogen turbine configured to be driven by excesshydrogen, derived from the steam reformer during hydrogen production408. In another embodiment, sequestration compression unit 430 includesa compressor that is driven by gas turbine 418. In yet anotherembodiment, sequestration compression unit 430 includes a compressorthat is driven by an electric motor.

As previously noted, sequestration compression unit 430 sends the carbondioxide rich stream away from facility 400 for off-site sequestration432. In an embodiment, sequestration 432 is an underground geologicalformation that includes at least a partially depleted hydrocarbonreservoir. In a related embodiment, at least some of the transferredcarbon dioxide rich stream is injectable into the hydrocarbon reservoir,to aid in enhanced oil recovery. In another example, the sequestrationsite is a region on top of a seabed, at a depth greater than threekilometers below sea level. In yet another example, the sequestrationsite is a region below a seabed.

FIG. 5 illustrates an exemplary schematic of a power plant 500 withhydrogen production. With comparison to power plant 400 in FIG. 4, powerplant 500 is configured to use at least about 90% hydrogen by volume asfuel to gas turbine, as described herein. Power plant 500 furtherincludes CO2 capture for the steam reformer.

Specifically, power plant 500 receives raw feed gas, such as naturalgas, from a pipeline 502 (e.g., a natural gas pipeline). As with thefacility 400 described above, natural gas pipeline 502 providing naturalgas to facility 500 may have associated with it one or more pig recoverysystems 533 or other pig-related systems, which may be significantsources of emissions that would typically be flared and/or vented to theatmosphere. In an embodiment, emissions from pig recovery system 533 aredirected to facility 500, for example, to hydrogen production 508 or tofuel gas conditioning 506.

Natural gas is sent from the pipeline 502 to hydrogen production 508.(Some quantity of natural gas may also pass directly from pipeline 502to fuel gas conditioning skid 506.) When natural gas is directed tohydrogen production 508, it can advantageously be used by a steamreformer as feedstock for a reformer. Specifically, in an embodiment,hydrogen production 508 is a steam reformer, such as a methane gasreformer, which is configured to generate hydrogen on-site. It should beappreciated that, in additional or alternative embodiments, hydrogenproduction 508 could be produced via other means, such as via anelectrolysis unit whereby water is split into hydrogen and oxygenthrough the use of electricity. Likewise, it should be appreciated that,in additional or alternative embodiments, hydrogen production 508 couldbe offsite, such as via an offsite supply of hydrogen 504, wherebyhydrogen may come into the LNG facility via pipeline, railcar, ship orother convenient means.

With that in mind, hydrogen production 508, such as via the steamreformer, allows for high temperature steam to react with methane, inthe presence of a catalyst, to produce hydrogen, carbon monoxide, andcarbon dioxide. Additional processes can be incorporated with hydrogenproduction 508, such as a water-gas shift reaction and/or pressure swingadsorption, to increase the yield of hydrogen. Excess hydrogen may begenerated on-site from the steam reformer. Such hydrogen may be storedin an on-site storage tank, and may be sent for consumption by otherssuch as onsite/offsite hydrogen users 510 within plant 500. Excess steamfrom hydrogen production 508 may be directed to various steam user 512,such as those described above.

Hydrogen may be provided to gas turbine 518 as fuel in highconcentrations (or to the fuel gas conditioning skid 506 prior to thegas turbine 518), for optimal combustion. It should be appreciated thatadditional hydrogen may be provided, beyond the supply from hydrogenproduction 508, such as from offsite hydrogen supply 504.

Fuel gas conditioning skid 506 takes streams hydrogen, and optionallysome amount of natural gas, and adjusts various physical conditions(e.g., temperatures, pressures, blends, and the like) to ensure that thegasses are conditioned for optimal combustion in a gas turbine 518.

Continuing on with respect to hydrogen production 508, for example, thefuel provided to gas turbine 518 may be a hydrogen-enriched hydrocarbonfuel. In an embodiment, within plant 500, fuel provided to gas turbine518 is at least 90 percent hydrogen by volume. The balance (i.e., up toabout 10% by volume) of the fuel gas stream may also include CO2, N2and/or oxygen in any proportions. In a further embodiment, fuel providedto gas turbine 518 is at least 95 percent hydrogen by volume.

In an embodiment, plant 500 further includes one or more powergenerators 520, such as electric generators, whereby gas turbine 518 iscoupled to the one or more electric generators 520; in this embodiment,facility 500 functions as a natural gas power generation facility.Namely, power from gas turbine 518 is transferred to power generator520, which delivers this electricity to an external electric grid 522.

Once combusted, gas from the gas turbine 518 may pass to a waste heatrecovery unit 524. The waste heat recovery unit 524 uses heat generatedby a combustion process, such as via combustion in gas turbine 518, toheat up a heat medium (e.g., hot oil or steam). The heated medium isthen used in various processes throughout facility 500 where additionalheat is required (e.g., amine regeneration, dehydration regeneration,and the like for pretreatment 500).

In an embodiment, waste heat recovery unit 524 communicates with acogeneration unit 528, which uses the waste heat from gas turbine 518 togenerate steam that, in turn, rotates a generator, such as powergenerator 520 or another generator. The electricity can then be used inother parts of the facility 500 or, alternatively, be sent to theelectric grid 522.

Combusted gas from the gas turbine 518 may eventually be vented to theatmosphere. Since the combustion gas from the gas turbine 518 isrelatively low in carbon dioxide and other greenhouse gases, forexample, as low as about 3.0% by volume, or more preferably even as lowas less than about 0.1% by volume (as the hydrogen concentration in thegas turbine fuel approaches 100%), this stream of combusted gas need notbe further treated in a post-combustion capture unit to remove carbondioxide, and the overall greenhouse gas emissions from facility 500 willnot be greatly increased by such venting of combustion gases to theatmosphere.

Meanwhile, a carbon dioxide containing gas from hydrogen production 508passes to capture facility 526, which generates a carbon dioxide richstream from the products of hydrogen production 508. In an alternativeembodiment, capture facility 526 may in addition receive combustiongases from gas turbine 518. Capture facility 526, similar to the captureunits discussed above, generates a carbon dioxide rich stream using anamine process to absorb carbon dioxide. Specifically, it will beappreciated that there are different types of amine depending on therelative concentrations of carbon dioxide in the flue gas stream.Natural gas fired turbines typically produce a relatively lessconcentrated carbon dioxide stream (e.g., approximately less than 5%) ascompared to a natural gas steam methane reformer 508 (e.g.,approximately 25%) and thus would generally use a different mixture toabsorb the carbon dioxide. Other processes can additionally oralternatively include use of ammonia or other related materials. Forexample, capture may include a chilled ammonia process for absorbingCO2, wherein excess steam is directable to the capture unit to provideheat for regenerating ammonia absorbent.

In an embodiment, capture facility 526 includes an amine absorber andliquid amine absorbent for absorbing carbon dioxide. In a relatedembodiment, hydrogen production 508 generates excess steam, which isdirectable to capture facility 526; this excess steam provides heat tocapture facility for regenerating the liquid amine absorbent.

After capture, a carbon dioxide rich gas passes to sequestrationcompression unit 530. More specifically, sequestration compression unit530 includes one or more knockout drums for collecting any remainingliquid in the gas stream. Sequestration compression unit 530 furtherincludes at least one compressor, configured to compress the carbondioxide rich stream, which may be then sent to a pipeline for off-sitesequestration 532. By sending the carbon dioxide rich stream to someform of sequestration, overall greenhouse gas emissions from facility500 are reduced. Other forms of sequestration (not shown in FIG. 5) maybe implemented, including for example sending the CO2 rich gas to anon-site or off-site storage tank, to a tank mounted on a rail car, or atank mounted on a truck-drawn trailer. After compression, thesequestered CO2 rich gas may advantageously be sold for a number ofwell-known applications and uses.

In an embodiment, sequestration compression unit 530 includes acompressor that is driven by steam generated from the steam reformerduring hydrogen production 508. In a related embodiment, the compressoris driven by a hydrogen turbine configured to be driven by excesshydrogen, derived from the steam reformer during hydrogen production508. In another embodiment, sequestration compression unit 530 includesa compressor that is driven by gas turbine 518. In yet anotherembodiment, sequestration compression unit 530 includes a compressorthat is driven by an electric motor.

As previously noted, sequestration compression unit 530 sends the carbondioxide rich stream away from facility 500 for off-site sequestration532. In an embodiment, sequestration 532 is an underground geologicalformation that includes at least a partially depleted hydrocarbonreservoir. In a related embodiment, at least some of the transferredcarbon dioxide rich stream is injectable into the hydrocarbon reservoir,to aid in enhanced oil recovery. In another example, the sequestrationsite is a region on top of a seabed, at a depth greater than threekilometers below sea level. In yet another example, the sequestrationsite is a region below a seabed.

As used in this specification, including the claims, the term “and/or”is a conjunction that is either inclusive or exclusive. Accordingly, theterm “and/or” either signifies the presence of two or more things in agroup or signifies that one selection may be made from a group ofalternatives.

The many features and advantages of the present disclosure are apparentfrom the written description, and thus, the appended claims are intendedto cover all such features and advantages of the disclosure. Further,since numerous modifications and changes will readily occur to thoseskilled in the art, the present disclosure is not limited to the exactconstruction and operation as illustrated and described. Therefore, thedescribed embodiments should be taken as illustrative and notrestrictive, and the disclosure should not be limited to the detailsgiven herein but should be defined by the following claims and theirfull scope of equivalents, whether foreseeable or unforeseeable now orin the future.

The invention is claimed as follows:
 1. A liquefied natural gas (LNG)production facility comprising: an acid gas removal unit configured toaccept a raw feed natural gas and generate an acid gas stream, a flashgas stream, and a purified natural gas stream, wherein the acid gasstream is directable to a sequestration compression unit; a dehydrationunit including a solid adsorbent, the dehydration unit configured toreceive the purified natural gas stream from the acid gas removal unitand provide a dry purified natural gas stream; a heavies removal unitconfigured to receive the dry purified natural gas stream from thedehydration unit and produce a liquid condensate product and a vaporproduct; a condensation storage tank configured to receive the liquidcondensate product from the heavies removal unit and allow for ventingof a first boil off gas (BOG); a liquefaction unit configured tocondense a natural gas vapor into a liquefied natural gas (LNG), theliquefaction unit comprising at least one electrically drivenrefrigerant compressor; an LNG storage tank configured to receive andstore the LNG from the liquefaction unit and allow for venting of asecond BOG; an LNG loading facility configured to receive the LNG fromthe LNG storage tank and transfer the LNG to a marine vessel comprisinga marine LNG storage tank, the LNG loading facility further configuredto allow for venting of a third BOG, at least one of the first BOG fromthe condensation storage tank or the third BOG from the LNG loadingfacility is directable as a feed to the sequestration compression unit;and the sequestration compression unit configured to compress and conveyat least one CO2-rich stream towards a sequestration site, wherein theat least one CO2-rich stream is selected from the group consisting ofthe first BOG from the condensation storage tank, the second BOG fromthe LNG storage tank, the third BOG from the LNG loading facility, thevapor product from the heavies removal unit, the acid gas stream fromthe acid gas removal unit, the flash gas stream from the acid gasremoval unit, and mixtures thereof, and the natural gas vapor condensedby the liquefaction unit is selected from the group consisting of thefirst BOG from the condensation storage tank, the second BOG from theLNG storage tank, the third BOG from the LNG loading unit, the vaporproduct from the heavies removal unit, and mixtures thereof.
 2. The LNGproduction facility of claim 1, wherein the sequestration site comprisesan underground geological formation comprising an at least partiallydepleted hydrocarbon reservoir.
 3. The LNG production facility of claim1, wherein the sequestration site comprises a region on top of a seabedand located at a depth greater than about 3.0 kilometers below a sealevel.
 4. The LNG production facility of claim 1, wherein thesequestration site comprises a region below a seabed.
 5. The LNGproduction facility of claim 1, wherein the sequestration compressionunit comprises an electric-driven compressor.
 6. The LNG productionfacility of claim 1, wherein the acid gas removal unit includes an amineabsorber and a liquid amine absorbent for absorbing CO2.
 7. The LNGproduction facility of claim 1 further comprising a marine vent systemadapted to receive a marine vessel tank gas from a marine LNG storagetank of a marine vessel and direct the marine vessel tank gas to feedany of: the sequestration compression unit; the liquefaction unit; orone or more facility flares, wherein the marine vessel tank gascomprises a BOG from one of the LNG, CO, CO2, N2 or mixtures thereof. 8.The LNG production facility of claim 4, wherein the seabed is located ata depth greater than about 3.0 kilometers below a sea level.
 9. The LNGproduction facility of claim 1, wherein the acid gas removal unitincludes a chilled ammonia process with an ammonia absorbent forabsorbing CO2.
 10. The LNG production facility of claim 1, where the LNGproduction facility is configured to receive a natural gas from a pigrecovery system and direct the natural gas as a feed to thesequestration compression unit.
 11. The LNG production facility of claim1, wherein the LNG production facility is configured to direct at leastone of the first, second, or third BOG to the sequestration compresssionunit.
 12. A process of producing a liquefied natural gas in a liquefiednatural gas (LNG) production facility comprising a liquefaction unitincluding at least one refrigerant compressor driven by an electricmotor, and the LNG production facility further comprising asequestration compression unit, an acid gas removal unit, a dehydrationunit including a solid adsorbent, a heavies removal unit, a condensationstorage tank, an LNG storage tank, and an LNG loading facility, theprocess comprising: accepting a raw feed natural gas and, generating anacid gas stream, a flash gas stream, and a purified natural gas streamby the acid gas removal unit; directing the acid gas stream to thesequestration compression unit; receiving the purified natural gasstream from the acid gas removal unit and providing a dry purifiednatural gas stream by the dehydration unit; receiving the dry purifiednatural gas stream from the dehydration unit and producing a liquidcondensate product and a vapor product by the heavies removal unit;receiving the liquid condensate product from the heavies removal unitand venting a first boil off gas (BOG) by the condensation storage tank;condensing a natural gas vapor into a liquefied natural gas (LNG) by theliquefaction unit; receiving and storing the LNG from the liquefactionunit and venting a second BOG by the LNG storage tank; receiving the LNGfrom the LNG storage tank, transferring the LNG to a marine vesselcomprising a marine LNG storage tank, and venting a third BOG by the LNGloading facility; and compressing and conveying at least one CO2-richstream towards a sequestration site by the sequestration compressionunit; and directing at least one of the first BOG from the condensationstorage tank or the third BOG from the LNG loading facility as a feed tothe sequestration compression unit, wherein the at least one CO2-richstream is selected from the group consisting of the first BOG from thecondensation storage tank, the second BOG from the LNG storage tank, thethird BOG from the LNG loading facility, the vapor product from theheavies removal unit, the acid gas stream from the acid gas removalunit, the flash gas stream from the acid gas removal unit, and mixturesthereof, and the natural gas vapor condensed by the liquefaction unit isselected from the group consisting of the first BOG from thecondensation storage tank, the second BOG from the LNG storage tank, thethird BOG from the LNG loading unit, the vapor product from the heaviesremoval unit, and mixtures thereof.
 13. The process of claim 12, whereinthe sequestration site comprises an underground geological formationcomprising an at least partially depleted hydrocarbon reservoir.
 14. Theprocess of claim 12, wherein the sequestration site comprises a regionon top of a seabed, the region located at a depth greater than about 3.0kilometers below a sea level.
 15. The process of claim 12, wherein thesequestration site comprises a region below a seabed.
 16. The process ofclaim 15, wherein the seabed is located at a depth greater than about3.0 kilometers below a sea level.
 17. The process of claim 12, whereinthe sequestration compression unit comprises an electric-drivencompressor.
 18. The process of claim 12, wherein the acid gas removalunit comprises a chilled ammonia process with an ammonia absorbent forabsorbing CO2, the process comprising absorbing the CO2 by the chilledammonia process.
 19. The process of claim 12, wherein the acid gasremoval unit includes an amine absorber and a liquid amine absorbent forabsorbing CO2, the process comprising absorbing the CO2 by the amineabsorber and the liquid amine absorbent.
 20. The process of claim 12comprising directing the flash gas stream to the sequestrationcompression unit.
 21. The process of claim 12 comprising directing eachof the first, second, and third BOG to the liquefaction unit.
 22. Theprocess of claim 12, wherein the LNG production facility furthercomprises a marine vent system, the process further comprising receivinga marine vessel tank gas from a marine LNG storage tank of a marinevessel by the marine vent system, and directing the marine vessel tankgas to feed any of: the sequestration compression unit; the liquefactionunit; or one or more facility flares, wherein the marine vessel tank gascomprises a BOG from one of the LNG, CO, CO2, N2 or mixtures thereof.